Boreholes, which are also commonly referred to as “wellbores” and “drill holes,” are created for a variety of purposes, including exploratory drilling for locating underground deposits of different natural resources, mining operations for extracting such deposits, and construction projects for installing underground utilities. A common misconception is that all boreholes are vertically aligned with the drilling rig; however, many applications require the drilling of boreholes with vertically deviated and horizontal geometries. A well-known technique employed for drilling horizontal, vertically deviated, and other complex boreholes is directional drilling. Directional drilling is generally typified as a process of boring a hole which is characterized in that the course of the borehole in the earth is in a direction other than vertical—i.e., the axes make an angle with the vertical plane (known as “vertical deviation”), and are directed in the azimuth plane.
Conventional directional boring techniques traditionally operate from a boring device that pushes or steers a series of connected drill pipes with a directable drill bit at the distal end thereof to achieve the borehole geometry. In the exploration and recovery of subsurface hydrocarbon deposits, such as petroleum and natural gas, the directional borehole is typically drilled with a rotatable drill bit that is attached to one end of a bottom hole assembly or “BHA.” A steerable BHA can include, for example, a positive displacement motor (PDM) or “mud motor,” drill collars, reamers, shocks, and underreaming tools to enlarge the wellbore. A stabilizer may be attached to the BHA to control the bending of the BHA to direct the bit in the desired direction (inclination and azimuth). The BHA, in turn, is attached to the bottom of a tubing assembly, often comprising jointed pipe or relatively flexible “spoolable” tubing, also known as “coiled tubing.” This directional drilling system—i.e., the operatively interconnected tubing, drill bit and BHA, is usually referred to as a “drill string.” When jointed pipe is utilized in the drill string, the drill bit can be rotated by rotating the jointed pipe from the surface, or through the operation of the mud motor contained in the BHA. In contrast, drill strings which employ coiled tubing generally rotate the drill bit via the mud motor in the BHA.
Drilling fluid is often used to aid the drilling of boreholes into the earth, for example, to remove cuttings from the borehole, control formation pressure, and cool, lubricate and support the bit and drilling assembly. Typically, the drilling fluid, which is more commonly referred to as “mud,” is pumped down the borehole through the interior of the drill string, out through nozzles in the end of the bit, and then upwardly in the annulus between the drill string and the wall of the borehole. During the ascent, some of the mud congeals, forming a cake on the exposed face of the wellbore, for example, to prevent the mud from being lost to the porous drilled formation. In addition, the pressure inside the formation can be partially or fully counterbalanced by the hydrostatic weight of the mud column in the hole. Since the mud has a variety of vital drilling functions, it must accordingly have comparable and reliable capabilities.
Many drilling parameters, such as measured depth, string rotary speed, weight on bit, downhole torque, surface torque, flow in, surface pressure, down hole pressure, bit orientation, bit deflection, etc., can be made available in real time. However, many drilling fluid properties—which can be critical to effective hydraulic modeling and hole cleaning performance—are not readily available in real time. Historically, a technician (or “mud engineer”) was required to perform a mud check once or twice every 12 hours, and report the measurement data every 24 hours. These measurements may include: density, rheology, electrical stability, filtration control, retort analysis (% solids, oil-water ratio), acidity (ph), salinity, and particle size distribution. This practice is accepted throughout the drilling industry; nevertheless, there are significant benefits to having the key mud properties tested and reported at multiple intervals designated by the operator. The on-site mud engineer, for example, typically has numerous other responsibilities in his/her daily routine and therefore cannot provide a constant stream of drilling fluid properties to a monitoring center, such as a remote real-time center. In addition, taking and/or generating such measurements are time consuming and inherently susceptible to human error. Automated mud measuring eliminates these drawbacks.
There are many systems available for measuring some of the characteristics of drilling mud. Sampling drilling fluid for instrumentation measurements, however, has many problems. Most drilling fluids are designed to plug small holes in the formation and are therefore heavily laden with solids. Moreover, the characteristics of the drilling fluid are constantly changing due to additions of solids and chemicals that make drawing a representative sample difficult. Partially suspended solids and partially dispersed chemicals can form pliable lumps that can plug sampling equipment. If left static, the solids in the drilling fluid tend to settle and plug small diameter tubing, valves, pumps and other fluid handling equipment.
There are various types of liquid-based drilling fluids: (1) water-based muds (WBM), which typically comprise a water-and-clay based composition, (2) oil-based muds (OBM), where the base fluid is a petroleum product, such as diesel fuel, and (3) synthetic-based muds (SBM), where the base fluid is a synthetic oil. In many cases, oil-based drilling fluids also have water or brine dispersed in the oil in significant proportions. In the course of drilling a well, a water-based fluid is often used in one section of the borehole, while an oil-based fluid will be used in a different section of the borehole. Switching between fluid types is fraught with problems for the sampling system and instrumentation because a thick sludge can form where the two fluid types come in contact with each other, which can plug flow passages. In addition, the drilling fluid sampling equipment and measurement instrumentation is frequently located in areas of a drilling rig with a high potential of being surrounded by high concentrations of flammable gases and fluids. As such, anything capable of generating a spark in normal operation or under fault conditions must be packaged to prevent ignition of the surrounding environment.